Storing CO2 with Enhanced Oil Recovery
ȱ
DOE/NETL-402/1312/02-07-08
February 7, 2008
Disclaimer
This report was prepared as an account of work sponsored by an agency of the
United States Government. Neither the United States Government nor any
agency thereof, nor any of their employees, makes any warranty, express or
implied, or assumes any legal liability or responsibility for the accuracy,
completeness, or usefulness of any information, apparatus, product, or process
disclosed, or represents that its use would not infringe privately owned rights.
Reference therein to any specific commercial product, process, or service by trade
name, trademark, manufacturer, or otherwise does not necessarily constitute or
imply its endorsement, recommendation, or favoring by the United States
Government or any agency thereof. The views and opinions of authors expressed
therein do not necessarily state or reflect those of the United States Government
or any agency thereof.
Storing CO2 with Enhanced Oil Recovery
DOE/NETL-402/1312/02-07-08
February 7, 2008
NETL Contact:
Lisa Phares
Office of Systems, Analyses and Planning
Prepared by:
Vello Kuuskraa
Robert Ferguson
Advanced Resources International
National Energy Technology Laboratory
www.netl.doe.gov
This page intentionally left blank
Table of Contents
1.0
Introduction
1
2.0
2.1.
2.2.
2.3.
Background
Key Feature of This New Report
Addressing Current Misconceptions Surrounding Storing CO2 with EOR
Report Outline
3
3
6
7
3.0
3.1.
3.2.
3.3.
Evaluating the Market for Captured CO2 Emissions Offered by EOR
Study Methodology
The Domestic Oil Resource Base
Technically Recoverable Oil Resources Using CO2-EOR
3.3.1.
3.3.2.
3.3.3.
3.3.4.
3.4.
Economically Recoverable Resources
3.4.1.
3.4.2.
3.4.3.
4.0
4.1.
4.2.
4.3.
4.4.
Using CO2-EOR to Recovery “Stranded” Oil
Current CO2-EOR Activity and Production
Evolution in CO2 Flooding Practices
Technically Recoverable Resources
Perspective on CO2-EOR Economics
Economically Recoverable Resources: Base Case
Economically Recoverable Resources: Sensitivity Cases
The Market for Storing CO2 with EOR
The CO2 Injection and Storage Process
Producing “Carbon Free” Domestic Oil
The Market for CO2
Market Demand for CO2: Power Plant Perspective
5.0 Using Sale of Captured CO2 Emission for “Early Market Entry” of CCS
Technology
5.1.
Economics of CCS
5.2.
Supporting “Early Market Entry” of CCS Technology
5.3.
Adding “Learning” to the “Early Market Entry” Opportunity
Appendix A Study Methodology
Appendix B Incorporation of Economically Feasible CO2 Demand for EOR into the
CarBen Model and the Electricity Market Module
Appendix C “Next Generation” CO2-EOR
9
9
9
15
15
17
20
25
28
28
29
29
34
34
35
35
39
48
48
50
53
List of Figures
Figure 1.
Figure 2.
Figure 3.
Figure 4.
Figure 5.
Figure 6A.
Figure 6B.
Figure 7.
Figure 8.
Figure 6.
Figure 7.
Figure 8.
Figure 9.
Figure 10.
ȱ
U.S. Basins/Regions Studied For Future CO2 Storage and Enhanced Oil Recovery
The Domestic Oil Resource Base
One-Dimensional Schematic Showing the CO2 Miscible Process.
U.S. CO2-EOR Activity
Growth of CO2-EOR Production in the U.S.
Science Behind Volume of CO2 Injection and Oil Recovery Efficiency: General Theory
Science Behind Volume of CO2 Injection and Oil Recovery Efficiency: Actual Practice
Overcoming the Effects of Geologic Complexity on CO2-EOR Performance
Evolution of “Industry Standard” for Volume CO2 Injection (“Slug Size”)
Economically Recoverable Domestic Oil Resources from CO2-EOR
NEMS Electricity Market Module
Advanced Coal Plants w/CCS Are Currently Uncompetitive in 2012 and 2020 (EIA’s AEO
2008 Reference Case)
Sale of Captured CO2 Emissions Can Help Make Coal Plants w/CCS Competitive
Sale of Captured CO2 Emissions Can Help Make Coal Plants w/CCS Competitive.
5
10
16
18
19
21
22
23
24
32
40
49
52
55
List of Tables
Table 1.
Table 2.
Table 3.
Table 4.
Table 5.
Table 6.
Table 7.
Table 8.
Table 9.
Table 10.
Table 11.
Table 12.
Table 13.
Table 14.
Table 15.
Table 16.
Table 17.
Table 18.
Table 19.
Table 20.
National In-Place, Conventionally Recoverable and “Stranded” Crude Oil Resources
Comparison of National and Data Base Domestic Oil Resource Base
Major Oil Reservoirs Screened as Favorable for CO2-EOR
Technically Recoverable Resources from Applying “State-of-the-Art” CO2-EOR: Data Base
and National Totals
Technically Recoverable Resources from Applying “State-of-the-Art” CO2-EOR: National
Totals
Illustrative Costs and Economics of a CO2-EOR Project
Economically Recoverable Resources from Applying “State-of-the-Art” CO2-EOR: National
Totals at Base Case Economics*
Economically Recoverable Resources from Applying “State-of-the-Art” CO2-EOR: National
Totals at Base Case and Alternative Oil Prices/CO2 Costs
Economically Feasible Market for CO2 for CO2-EOR: Base Case* (Eleven Basins/Areas)
Economically Feasible Market Demand for CO2 by CO2-EOR: Alternative Cases (Eleven
Basins/Areas)
Economically Feasible Market Demand for CO2 by EOR: NEMS/EMM Power Generation
Regions
Simplified Crosswalk Between the EMM Regions and States
Economically Feasible Market Demand for CO2 by EOR: NEMS/EMM Power Generation
Regions
Existing CO2 Supplies
Comparison of Net CO2 Demand (for EOR) with Potential Captured CO2 Emissions from
Coal-Fueled Power Plants
Relationship of CO2 Sales Price to Cost Offsets in the Coal-Fueled Power Sector (Year
2020)
EIA Reference Case Year 2012 and Year 2020 Costs of Electricity
Cost of Electricity in Year 2020 with Sale of CO2
Year 2020 Costs of Electricity with Accelerated “Learning” Based Cost Reductions
Year 2020 Cost of Electricity with “Learning” and CO2 Sale Offset
12
13
14
26
27
28
30
31
37
38
41
42
44
45
47
50
50
51
53
54
Storing CO2 with Enhanced Oil Recovery
1.0
Introduction
CO2 enhanced oil recovery (CO2-EOR) offers the potential for storing significant
volumes of carbon dioxide emissions while increasing domestic oil production. Four
notable benefits would accrue from integrating CO2 storage and enhanced oil recovery:
‚
First, CO2-EOR provides a large, “value added” market for sale of CO2
emissions captured from new coal-fueled power plants. The size of this
market is on the order of 7,500 million metric tons between now and 2030.
Sales of captured CO2 emissions would help defray some of the costs of
installing and operating carbon capture and storage (CCS) technology.
These CO2 sales would support “early market entry” of up to 49 (one GW
size) installations of CCS technology in the coal-fueled power sector;
‚
Second, storing CO2 with EOR helps bypass two of today’s most serious
barriers to using geological storage of CO2 - - establishing mineral (pore
space) rights and assigning long-term liability for the injected CO2;
‚
Third, the oil produced with injection of captured CO2 emissions is 70%
“carbon-free”, after accounting for the difference between the carbon
content in the incremental oil produced by EOR and the volume of CO2
stored in the reservoir . With “next generation” CO2 storage technology
and a value for storing CO2, the oil produced by EOR could be 100+%
“carbon free”;
‚
Fourth, the 39 to 48 billion barrels of economically recoverable domestic
oil economically recoverable from storing CO2 with EOR would help
displace imports, supporting a path toward energy independence. It could
also help build pipeline infrastructure subsequently usable for storing CO2
in saline formations.
1
The purpose of this report, which updates and adds to a previously issued series
of “basin studies”, is to examine and further quantify the benefits of integrating CO2
storage with enhanced oil recovery. The report also updates the size of the CO2
market available from EOR and how this market could support “early market entry” of
CCS technology in the coal-fueled electric power sector.
2
2.0
Background
2.1.
Key Feature of This New Report
In 2004 and 2005, Advanced Resources International, with sponsorship by the
U.S. Department of Energy’s Office of Fossil Energy, issued a series of ten “basin
reports”. These reports examined the domestic CO2 storage and oil recovery potential
offered by expanded development and application of CO2-EOR technology. This report
entitled, “Storing CO2 with Enhanced Oil Recovery”, provides a major update to this
past set of data and information. For example, the initial chapter of the report which
serves to quantify the size of the CO2 market offered by EOR, contains the following
new features:
‚
A significant number, nearly 500, new oil reservoirs have been added to
the data base, including oil reservoirs in the Appalachian Basin. The
assessment now includes 2,012 oil reservoirs accounting for nearly threequarters of the U.S. oil resource base in 27 states, Figure 1. These new
oil reservoirs were made available for this study from Advanced
Resources proprietary data base;
‚
Improvements and updates have been made to the well spacing and CO2
injection portions of the model. Oil field cost data have been updated and
indexed to year 2006-2007. These updates and improvements are based
on internal work undertaken by Advanced Resources; and
‚
An expanded set of oil prices and a revised oil price/CO2 cost relationship
have been incorporated into the economic analyses, as presented later in
this report.
ȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱ
ȱTheȱAdvancedȱResourcesȱcompletedȱseriesȱofȱtenȱ“basinȱstudies”ȱwereȱtheȱfirstȱtoȱcomprehensivelyȱaddressȱCO2ȱ
storageȱcapacityȱfromȱcombiningȱCO2ȱstorageȱandȱCO2ȬEOR.ȱȱTheseȱtenȱ“basinȱstudies”ȱcoveredȱ22ȱofȱtheȱoilȱ
producingȱstatesȱplusȱoffshoreȱLouisianaȱandȱincludedȱ1,581ȱlargeȱ(>50ȱMMBblsȱOOIP)ȱoilȱreservoirs,ȱaccountingȱforȱ
twoȱthirdsȱofȱU.S.ȱoilȱproduction.ȱȱTheseȱreportsȱareȱavailableȱonȱtheȱU.S.ȱDepartmentȱofȱEnergy’sȱwebȱsiteȱat:ȱ
http://www.fe.doe.gov/programs/oilgas/eor/Ten_BasinȬOriented_CO2ȬEOR_Assessments.html.ȱ
3
The later chapters of this report examine how much of the CO2 emissions
captured by the power and industrial sectors could be sold to the EOR industry and how
the sale of these captured CO2 emissions would support the “early market entry” of new
coal-fueled power plants equipped with CO2 capture technologies.
4
5
Figure 1. U.S. Basins/Regions Studied For Future CO2 Storage and Enhanced Oil Recovery
JAF02709.PPT
The 27 states with shading are included in the eleven
Advanced Resources International updated “basin studies”
of CO2 storage with enhanced oil recovery.
2.2.
Addressing Current Misconceptions Surrounding Storing CO2 with EOR
Various analysts and studies have discussed the potential for storing CO2 with
enhanced oil recovery but have noted (incorrectly) that this option is quite small or is
counter productive to reducing CO2 emissions. For example, the “IPCC Special Report
on Carbon Dioxide Capture and Storage”, while recognizing that depleted oil fields
could provide an attractive, early option for storing CO2 (particularly with CO2-EOR),
concluded that oil fields would provide only a relatively small volume of CO2 storage
capacity. The report states:
“Enhanced oil recovery operations have the lowest capacity of all
forms of CO2 geologic storage, estimated globally at 61 to 123 billion tons
of CO2 . . . it is important to note that CO2 EOR, as practiced today, is not
engineered to maximize CO2 storage. In fact, it is optimized to maximize
revenues from oil production, which in many cases requires minimizing the
amount of CO2 retained in the reservoir. In the future, if storing CO2 has
an economic value, co-optimizing CO2 storage and EOR may increase
capacity estimates.”
In a similar vein, the website Climate Progress contains the headline - - “Rule
Four of Offsets: No Enhanced Oil Recovery”. The website continues by stating:
“Capturing CO2 and injecting it into a well to squeeze more oil out
of the ground is not real carbon sequestration. . . .CO2 used for enhanced
oil recovery (EOR) does not reduce net carbon emissions and should not
be sold to the public as a carbon offset.”
Finally, the ERS/IEA Report: “Carbon Dioxide Capture and Storage in the Clean
Development Mechanism (CDM)” sets forth two assumptions that shape the report’s
view of storing CO2 with EOR:
‚
As CO2-EOR projects reach the end of their life, greater volumes of CO2
will be produced (and emitted); and
6
‚
CO2-EOR projects will result in increased carbon emissions from
incremental oil production above a No Further Activity (NFA) baseline.
The ERS/IEA report continues by stating that, to be acceptable, a CO2-EOR
project would need to provide a full carbon balance across the whole life cycle of the
project, including emissions from combustion of the incremental oil produced. The
ERS/IEA report recommends that for acceptance by CDM, CO2-EOR would need to
demonstrate net emission reductions.
One of the additional purposes of this new report is to address, and hopefully
dispel, some of the misconceptions that have arisen around the topic of storing CO2
with enhanced oil recovery by showing that: (1) for the U.S. (and by extension for the
world), the CO2 storage capacity offered by CO2-EOR is large, and when innovatively
engineered, can be larger still; (2) essentially all the purchased CO2 is reinjected and
thus stored in the original (or an adjacent) oil reservoir; and (3) the incremental oil
produced is 70% “carbon free”, creating net emission reductions - - and thus
additionality - - by displacing conventionally produced oil imports that are 0% “carbon
free” or corn-based ethanol, that is only 10 to 15% “carbon free” (and a net contributor
of CO2 emissions when coal is used as the process fuel).
2.3.
Report Outline
The report begins with a summary presentation of three topics central to
establishing the market for CO2 offered by EOR - - what is the size and nature of the
domestic oil resource base; how much of this resource base is applicable to and can be
recovered with CO2-EOR; and, what portion of this technically recoverable resource
would be economic at alternative oil prices and CO2 costs?
The report then examines the market opportunity for selling captured CO2
emissions to the EOR industry and storing these emissions in oil reservoirs using CO2EOR, giving particular attention to the capture and productive use of CO2 emissions
from the nation’s large and growing fleet of coal-fueled power plants.
7
A series of appendices provide supporting data and technical information for the
analytical results discussed in the main report. Additional discussion of key topics such
as the oil recovery and cost models and the data bases used in the analyses are
available in the previously published set of ten “basin studies” and thus are not repeated
in this updated report. The previously prepared “basin study” reports can be accessed
at http://www.fe.doe.gov/programs/oilgas/publications/.
8
3.0
Evaluating the Market for Captured CO2 Emissions Offered by
EOR
The size and value of the market for captured CO2 emissions offered by
enhanced oil recovery rests on three pillars: (1) the size and nature of the domestic
crude oil resource base, particularly the large portion of this resource base
unrecoverable with existing primary and secondary oil recovery methods; (2) the ability
of CO2-EOR to recovery a portion of this currently unrecoverable (“stranded”) domestic
oil, while efficiently storing CO2; and (3) the impact of alternative oil prices and CO2
costs on the volume of oil that could be economically produced. These three topics are
examined, in brief, in this section of the report.
3.1.
Study Methodology
A six part methodology was used to assess the CO2 storage and EOR potential
of domestic oil reservoirs. The six steps were: (1) assembling the Major Oil Reservoirs
Data Base; (2) calculating the minimum miscibility pressure; (3) screening reservoirs for
CO2-EOR; (4) calculating oil recovery; (5) assembling the cost and economic model;
and, (6) performing economic and sensitivity analyses.
Appendix A provides additional detail on the methodology used in this study.
3.2.
The Domestic Oil Resource Base
The U.S. has a large, established oil resource base, on the order of 596 billion
barrels originally in-place. About one-third of this resource base, nearly 196 billion
barrels, has been recovered or placed into proved reserves with existing primary and
secondary oil recovery technologies. This leaves behind a massive target of 400 billion
barrels of “technically stranded” oil, Figure 2 .
ȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱ
ȱWhenȱlessȱestablishedȱdomesticȱoilȱresources,ȱsuchȱasȱundiscoveredȱoil,ȱtarȱsands,ȱandȱoilȱtrappedȱinȱ
residualȱoilȱzonesȱareȱincluded,ȱtheȱ“stranded”ȱoilȱresourceȱapproachesȱ1,000ȱbillionȱbarrels.ȱȱForȱfurtherȱ
informationȱonȱthisȱtopicȱseeȱChapterȱ3ȱ(pagesȱ183ȱandȱ184)ȱofȱtheȱrecentlyȱissuedȱNationalȱPetroleumȱ
Councilȱreportȱ“HardȱTruths,ȱFacingȱtheȱHardȱTruthsȱaboutȱEnergy”ȱJuly,ȱ2007,ȱ
http://www.npchardtruthsreport.org/ȱ
9
JAF02709.PPT
*Excludes deep-water GOM.
Source: Advanced Resources International (2008)
Cumulative Production
175 Billion Barrels
10
Figure 2. The Domestic Oil Resource Base
Proved Reserves
21 Billion Barrels
Future Challenge
400 Billion Barrels
“Stranded” Oil In-Place: 400 B Barrels*
Original Oil In-Place: 596 B Barrels*
Large Volumes Of Domestic Oil Remain “Stranded” After Traditional Primary/Secondary Oil Recovery
Table 1 provides a tabulation of the national in-place, conventionally recoverable
and “stranded” oil in the eleven “basins” addressed by this study. The table shows that
much of the “stranded” oil resides in East and Central Texas (74 billion barrels), the
Mid-Continent (66 billion barrels), and the Permian Basin of West Texas and New
Mexico (62 billion barrels). California, Alaska, the Gulf Coast and the Rockies also have
significant volumes of “stranded” oil.
The Advanced Resources’ Major Oil Reservoirs Data Base of 2,012 distinct oil
reservoirs contains 74% (437.8 billion barrels of OOIP out of the national total of 595.7
billion barrels of OOIP), of the domestic oil resource, Table 2.
The data base coverage for individual basins/areas ranges from 59% for the MidContinent to 97% for Alaska. As such, the Major Oil Reservoir Data Base provides a
robust foundation for estimating the national oil recovery potential from CO2-EOR.
Not all of the domestic oil resource is technically amenable to CO2-EOR.
Favorable reservoir properties for CO2-EOR include sufficiently deep formations with
lighter (higher gravity) oil favorable for miscible CO2-EOR. A portion of the shallower oil
reservoirs with heavier (lower gravity) oil may be amenable to immiscible CO2-EOR.
Table 3 provides a basin/area level tabulation of the 2,012 reservoirs in the Major
Oil Reservoirs Data Base, showing that only 1,111 reservoirs (containing 319 billion
barrels of OOIP) screened as being amenable to miscible and immiscible CO2-EOR.
More than half of the oil reservoirs in California, particularly the shallower heavy oil
fields, are screened as unfavorable for CO2-EOR while the great bulk (over 80%) of the
geologically favorable oil reservoirs in the Permian Basin are screened as favorable for
CO2-EOR.
11
Table 1. National In-Place, Conventionally Recoverable and “Stranded” Crude Oil Resources
Basin/Area
OOIP*
(Billion Barrels)
Conventionally
Recoverable
(Billion Barrels)
ROIP**
“Stranded”
(Billion Barrels)
1. Alaska
67.3
22.3
45.0
2. California
83.3
26.0
57.3
3. Gulf Coast (AL, FL, MS, LA)
44.4
16.9
27.5
4. Mid-Continent (OK, AR, KS, NE)
89.6
24.0
65.6
5. Illinois/Michigan
17.8
6.3
11.5
6. Permian (W TX, NM)
95.4
33.7
61.7
7. Rockies (CO,UT,WY)
33.6
11.0
22.6
8. Texas, East/Central
109.0
35.4
73.6
9. Williston (MT, ND, SD)
13.2
3.8
9.4
10. Louisiana Offshore
28.1
12.4
15.7
11. Appalachia (WV, OH, KY, PA)
14.0
3.9
10.1
595.7
195.7
400.0
Total
*Original Oil in Place, in all reservoirs in basin/area;
** Remaining Oil in Place, in all reservoirs in basin/area.
Source: Advanced Resources Int’l, 2008.
12
Table 2. Comparison of National and Data Base Domestic Oil Resource Base
Basin/Area
National
OOIP*
(Billion Barrels)
Data Base
OOIP*
(Billion Barrels)
Data Base
Coverage
(%)
1. Alaska
67.3
65.4
97
2. California
83.3
75.2
90
3. Gulf Coast (AL, FL, MS, LA)
44.4
26.4
60
4. Mid-Continent (OK, AR, KS, NE)
89.6
53.1
59
5. Illinois/Michigan
17.8
12.0
67
6. Permian (W TX, NM)
95.4
72.4
76
7. Rockies (CO,UT,WY)
33.6
23.7
70
8. Texas, East/Central
109.0
67.4
62
9. Williston (MT, ND, SD)
13.2
9.4
71
10. Louisiana Offshore
28.1
22.2
79
11. Appalachia (WV, OH, KY, PA)
14.0
10.6
76
595.7
437.8
74
Total
*Original Oil In-Place, in all reservoirs in basin/area;
Source: Advanced Resources Int’l, 2008.
13
Table 3. Major Oil Reservoirs Screened as Favorable for CO2-EOR
Basin/Area
1. Alaska
Major Oil Reservoirs Data Base
# of Total
# Favorable
Reservoirs
For CO2-EOR
42
32
2. California
3. Gulf Coast (AL,FL, MS, LA)
4. Mid-Continent (OK, AR, KS, NE)
5. Illinois/Michigan
6. Permian (W TX, NM)
7. Rockies (CO,UT,WY)
8. Texas, East/Central
9. Williston (MT, ND, SD)
10. Louisiana Offshore
11. Appalachia (WV, OH, KY, PA)
Total
14
187
86
298
155
246
102
172
72
228
190
187
92
213
161
95
54
156
99
188
68
2,012
1,111
3.3.
Technically Recoverable Oil Resources Using CO2-EOR
3.3.1. Using CO2-EOR to Recovery “Stranded” Oil
Numerous scientific as well as practical reasons account for the large volume of
“stranded” oil, unrecoverable with primary and secondary methods. These include: oil
that is bypassed due to poor waterflood sweep efficiency; oil that is physically
unconnected to a wellbore; and, most importantly, oil that is trapped by viscous,
capillary and interfacial tension forces as residual oil in the pore space.
Injection of CO2 helps lower the oil viscosity and trapping forces in the reservoir.
Additional well drilling and pattern realignment for the EOR project helps contact
bypassed and occluded oil. These actions enable a portion of this “stranded oil” to
become mobile, connected to a wellbore and thus recoverable.
Miscible CO2-EOR is a multiple contact process involving interactions between
the injected CO2 and the reservoir’s oil. During this multiple contact process, CO2
vaporizes the lighter oil fractions into the injected CO2 phase and CO2 condenses into
the reservoir’s oil phase. This leads to two reservoir fluids that become miscible (mixing
in all parts), with favorable properties of low viscosity, enhanced mobility and low
interfacial tension.
The primary objective of miscible CO2-EOR is to remobilize and dramatically
reduce the after-waterflooding residual oil saturation in the reservoir’s pore space.
Figure 3 provides a one-dimensional schematic showing the various fluid phases
existing in the reservoir and the dynamics of the CO2 miscible process.
15
Miscibility is Developed in This Region
(CO 2 and Oil Form Single Phase)
Pure
CO2
CO2
Condensing
Into Oil
CO2 Vaporizing
Oil Components
Original
Oil
Direction of Displacement
JAF02709.PPT
Figure 3. One-Dimensional Schematic Showing the CO2 Miscible Process.
16
3.3.2. Current CO2-EOR Activity and Production
According to the latest tabulation of CO2-EOR activity in the U.S., the 2006 EOR
Survey published by the Oil and Gas Journal, approximately 237 thousand barrels per
day of incremental domestic oil is being produced by 86 CO2-EOR projects, distributed
broadly across the U.S.
Figure 4 provides the location of the currently active 86 CO2-EOR projects,
noting their CO2 supply sources. Figure 5 tracks the steady growth in CO2-EOR
production for the past 20 years, noting that although new activities are underway in the
Gulf Coast and the Rockies, the great bulk of CO2-EOR is still being produced from the
Permian Basin.
Given the significant number of new and expanded CO2-EOR projects launched
in 2006 and 2007, we anticipate that the next EOR Survey, due to be published in the
spring of 2008, will show substantial increases in domestic CO2-EOR activity and oil
production.
17
2
JAF02709.PPT
01
9 94
.C D
R
1
9
18
Val Verde
Verde
Val
Gas Plants
Plants
Gas
McElmo Dome
Dome
McElmo
Sheep
Mountain
Sheep Mountain
Bravo
Dome
JA Dome
Bravo
F
LaBarge
LaBarge
Gas
Plant
Gas Plant
Dakota Coal
Coal
Dakota
Gasification
Gasification
Plant
Plant
6
6
Jackson
Jackson
Dome
Dome
Enid Fertilizer
Fertilizer
Enid
Plant
Plant
3
Antrim Gas
Gas
Antrim
Plant
Plant
CO 2 Pipeline
Industrial CO2 Source
Natural CO 2 Source
Number of CO 2-EOR Projects
Figure 4. U.S. CO2-EOR Activity
57
1
86
0
1986
50,000
100,000
150,000
200,000
250,000
1988
JAF02709.PPT
1992
1994
Year
1996
1998
2000
19
Figure 5. Growth of CO2-EOR Production in the U.S.
1990
Permian Basin
Gulf Coast/Other
Mid-Continent
Rocky Mountains
Source: Oil and Gas Journal, April, 2006.
Enhanced Oil Recovery (barrels/day)
2002
2004
2006
JAF2006016.XLS
3.3.3. Evolution in CO2 Flooding Practices
Considerable evolution has occurred in the design and implementation of CO2EOR technology since it was first introduced. Notable changes include: (1) use of much
larger (up to 1 HCPV) volumes of CO2; (2) incorporation of tapered WAG (water
alternating with gas) and other methods for mobility control; and (3) application of
advanced well drilling and completion strategies to better contact previously bypassed
oil. As a result, the oil recovery efficiencies of today’s better designed “state-of-the-art”
CO2-EOR projects have steadily improved.
Two key assumptions underlie the oil recovery performance calculated for this
study by the ARI/PROPHET model (see Appendix A) for “state-of-the-art” CO2-EOR:
‚
First is the injection of much larger volumes of CO2 (1 HCPV), rather than
the smaller (0.4 HCPV) volumes used in the past;
‚
Second are the rigorous CO2-EOR monitoring, management and, where
required, remediation activities that help assure that the larger volumes of
injected CO2 contact more of the reservoir’s pore volume and residual oil
rather than merely channel through high permeability streaks in the
reservoir.
In addition to these two central assumptions, the calculated oil recovery in the
ARI/PROPHET model assumes appropriate well spacing (including the drilling of new
infill wells), the use of a tapered WAG process, the maintenance of miscibility pressure
throughout the reservoir, and the reinjection of CO2 produced with oil.
Figures 6A and 6B provide the scientific and practical basis for using larger
volumes of CO2 injection. Figure 7 illustrates how rigorous monitoring and well
remediation can be used to target injected CO2 to reservoir strata with high remaining
oil saturation, helping reduce ineffective CO2 channeling.
Figure 8, using information from Occidental Petroleum (Oxy Permian), provides a
17 year snapshot of the evolution of the “industry standard” for the most effective
volume of CO2 injection (the optimum “slug size”).
20
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1.0
0
0.2
0.5
1
Vp
5
Mobility Ratio, M
2
10 20
50 100 200
500 1000
Sweep Efficiency in Miscible Flooding
a
M
0.6
0.4
0.2
0.1
1.0
2.0
1.5
3.0
5.0
V pD
0.570
1.00
Source: After Claridge (April 1972) (Mobility Ratio of 25)
0.515
0.440
0.345
0.80
0.60
0.40
Injected CO2
(HCPV)
Sweep
Efficiency
(RPV)
Oil Recovery Efficiency
vs. CO2 Injection
+65%
+49%
+28%
Incremental
Sweep
Efficiency
(%)
21
Figure 6A. Science Behind Volume of CO2 Injection and Oil Recovery Efficiency: General Theory
JAF02709.PPT
Source: Claridge, E.L., “Prediction of Recovery in Unstable Miscible
Displacement”, SPE (April 1972).
Note: VpD is displaceable fluid pore volumes of CO2 injected.
Sweep Efficiency, EA
Petroleum engineering science confirms that using increased volumes of
CO2 leads to increased reservoir sweep efficiency.
D
.
vs
.T.
tB
10
JAF02709.PPT
40
50
0.2 HCPV
0.4 HCPV
0.6 HCPV
0.8 HCPV
Latest objective is to inject 480 Bcf (~1
HCPV) of CO2.
Initial objective was to inject 260 Bcf of
CO2, equal to 55% HCPV, (0.4 HCPV
purchased; 0.15 HCPV recycled) at a 2:1
WAG ratio.
The CO2-EOR WAG project at Means
(San Andres Unit) was implemented as
part of an integrated reservoir
development plan and involve the drilling
of 205 new producers and 158 new
injectors.
22
Figure 6B. Science Behind Volume of CO2 Injection and Oil Recovery Efficiency: Actual Practice
30
20
Years
Means (San Andres) @ 2:1 WAG Ratio
Source: SPE 24928 (1992)
0
0
5
10
15
20
25
Effect of Solvent Bank Size on Oil Recovery
Incremental Tertiary Recovery - % OOIP
100
Water
Distance, ft
200
Layer 1 (High Sor, Low k)
300
1839 Days
(Channeling in
Layer 2)
478 Days
(Breakthrough
In Layer 2)
Layer 2
368 Days
(Low Sor, High k)
Relative Location of the CO2/Water Front
Higher oil saturation portion of reservoir is
inefficiently swept.
JAF02709.PPT
20
60
80
% Injected Before
40
100
0
20
23
60
80
% Injected After
40
(After)
Source: “SACROC Unit CO2 Flood: Multidisciplinary Team Improves Reservoir Management and
Decreases Operating Costs”, J.T. Hawkins, et al., SPE Reservoir Engineering, August 1996.
6,900 0
(Before)
Well 27-6 Injection Profile
CO2 channeling reduced with well workover.
6,350
•
Figure 7. Overcoming the Effects of Geologic Complexity on CO2-EOR Performance
Source: Adapted by Advanced Resources Int’l from “Enhanced Oil Recovery”, D.W. Green and G. P.
Willhite, SPE, 1998.
0
•
Rigorous monitoring and well remediation can be used to help target injected CO 2 to reservoir strata with high
residual oil saturation.
Depth
100
1989
1992
1994
1996
2001
EDU WAG & start off CO2 injection in WAC, FIA, B8 FIA
Non performing FIA patterns stopped (~20% slug size)
EDU 40% to 60% CO2 slug size increase approved
EDU 60% to 80% CO2 slug size increase approved
EDU 80% to 100% CO2 slug size increase approved
JAF02709.PPT
24
Figure 8. Evolution of “Industry Standard” for Volume CO2 Injection (“Slug Size”)
Occidental Petroleum (Oxy Permian) is the industry leader for CO2-EOR, in terms of number of large
projects, volume of CO2 used, and volumes of oil production.
Source: OXY Permian 2006
1984
Started
Start of CO2 injection in EDU with 40% slug size
Eastern Denver Unit (Wasson Oil Field) CO2-EOR Project
The oil recovery calculations contained in this study rely on these “state-of-theart” practices. As such, the calculated oil recovery efficiencies expected from CO2-EOR
are somewhat higher than have been achieved by older CO2-EOR projects. However,
they are representative of the “best practices” being employed by technically
sophisticated operations and current CO2-EOR projects.
3.3.4. Technically Recoverable Resources
Our reservoir-by-reservoir assessment of the 1,111 large oil reservoirs amenable
to CO2-EOR shows that a significant volume, 64 billion barrels, of domestic oil may be
recoverable with state-of-the-art application of CO2-EOR. Extrapolating the data base
to national-level results indicates that 87.1 billion barrels of domestic oil may become
recoverable by applying “state-of-the-art” CO2-EOR, Table 4.
Subtracting the 2.3 billion barrels of oil that has already been produced and
proven by CO2-EOR (as of 2004), the application of CO2-EOR would add 84.8 billion
barrels of incremental domestic oil supplies, Table 5. For perspective, the current
domestic proved crude oil reserves are 21 billion barrels, as of the end of 2006.
Not surprisingly, the Permian Basin of West Texas and New Mexico tops the list
with its world class size, favorable geology and carbonate reservoirs. In addition,
significant technically recoverable resource potential also exists in East and Central
Texas, Alaska and the Mid-Continent as well as the Gulf Coast, California and the
Louisiana offshore.
25
Table 4. Technically Recoverable Resources from Applying “State-of-the-Art” CO2-EOR:
Data Base and National Totals
Basin/Area
DATA BASE
OOIP
Favorable
Technically
for
Recoverable
CO2-EOR
(Billion
(Billion
Barrels)
Barrels)
OOIP
(Billion
Barrels)
NATIONAL
OOIP
(Billion
Barrels)
Technically
Recoverable
(Billion
Barrels)
1. Alaska
65.4
64.5
12.0
67.3
12.4
2. California
75.2
31.6
5.7
83.3
6.3
3. Gulf Coast (AL, FL, MS, LA)
26.4
20.2
4.2
44.4
7.0
4. Mid-Continent (OK, AR, KS, NE)
53.1
28
6.4
89.6
10.7
5. Illinois/Michigan
12.0
4.6
0.8
17.8
1.2
6. Permian (W TX, NM)
72.4
63.1
13.5
95.4
17.8
7. Rockies (CO,UT,WY)
23.7
18.0
2.9
33.6
4.2
8. Texas, East/Central
67.4
52.4
10.9
109.0
17.6
9.4
7.2
1.8
13.2
2.5
10. Louisiana Offshore
22.2
22.1
4.6
28.1
5.8
11. Appalachia (WV, OH, KY, PA)
10.6
7.4
1.2
14.0
1.6
437.8
319.1
64
595.7
87.1
9. Williston (MT, ND, SD)
Total
26
Table 5. Technically Recoverable Resources from Applying “State-of-the-Art” CO2-EOR:
National Totals
Technically
Recoverable
(Billion Barrels)
1. Alaska
Existing
Incremental
CO2-EOR
Production/
Reserves
Technically
Recoverable
(Billion Barrels)
12.4
-
12.4
6.3
-
6.3
7
*
7
10.7
-0.1
10.6
1.2
-
1.2
6. Permian (W TX, NM)
17.8
-1.9
15.9
7. Rockies (CO,UT,WY)
4.2
-0.3
3.9
8. Texas, East/Central
17.6
-
17.6
9. Williston (MT, ND, SD)
2.5
-
2.5
10. Louisiana Offshore
5.8
-
5.8
11. Appalachia (WV, OH, KY, PA)
1.6
-
1.6
87.1
-2.3
84.8
2. California
3. Gulf Coast (AL, FL, MS, LA)
4. Mid-Continent (OK, AR, KS, NE)
5. Illinois/Michigan
Total
27
3.4.
Economically Recoverable Resources
3.4.1. Perspective on CO2-EOR Economics
Conducting a CO2-EOR project is capital intensive and costly, entailing the
drilling and/or reworking of wells, installing a CO2 recycle plant, and constructing CO2
gathering and transportation pipelines. However, in general, the single largest cost of
the project is the purchase of CO2. As such, operators strive to optimize and reduce its
purchase and injection, where possible.
The recent increases in domestic oil prices have significantly improved the
economics outlook for conducting CO2-EOR. However, oil field costs have also
increased sharply, reducing the economic margin essential for justifying this still
emerging (and to many operators, novel and risky) oil recovery option.
The cost and economic margins of a representative, reasonably favorable CO2EOR project are provided, for illustrative purposes, in Table 6 below. (The reader is
advised that considerable reservoir-specific variations exist around the cost and
economic margin values shown in the illustrative CO2-EOR project.)
Table 6. Illustrative Costs and Economics of a CO2-EOR Project
Assumed Oil Price ($/B)
$70
Less:
‚
Gravity/Basis Differentials, Royalties and Production Taxes
Net Wellhead Revenues ($/B)
($15)
$55
Less:
‚
Capital Costs
‚
CO2 Costs (@ $2/Mcf for purchase; $0.70/Mcf for recycle)
‚
Well/Lease O&M
($5 to $10)
($15)
($10 to $15)
Economic Margin, Pre-Tax ($/B)
$15 to $25
28
Given the significant front-end investment in wells, recycle equipment and
purchase of CO2 (equivalent to $20 to $25 per barrel) and the time delay in reaching
peak oil production, pre-tax economic margins on the order of the front-end investment
will be required to achieve economically favorable rates of return. Oil reservoirs with
higher capital cost requirements and less favorable CO2 to oil ratios would not achieve
an economically justifiable return on investment, requiring advanced, more efficient
CO2-EOR technology and/or credits for storing CO2.
3.4.2. Economically Recoverable Resources: Base Case
In the Base Case, 45 billion barrels of incremental oil become economically
recoverable from applying CO2-EOR. The Base Case evaluates the CO2-EOR
potential using an oil price of $70 per barrel (constant, real) and a CO2 cost of $45 per
metric ton ($2.38 per Mcf) (delivered at pressure to the field, constant and real).
The $70 per barrel oil price is used as the project investment oil price,
established using the average price of crude oil over the past three years, consistent
with the investment oil price methodology used in NEMS.
Table 7 presents the basin-by-basin tabulation of economically recoverable
resources from applying “state-of-the-art” CO2-EOR technology under Base Case
economics.
3.4.3. Economically Recoverable Resources: Sensitivity Cases
To gain insights as to how changes in oil prices would influence the volumes of
economically recoverable resources from applying CO2-EOR, the story examined one
lower and two higher oil price cases (and their associated CO2 costs).
Table 8 presents the 45 billion barrels of domestic oil recovery potentially
available from CO2-EOR at the Base Case oil price and CO2 cost. This increases to
47.9 to 48.3 billion barrels of higher ($90 to $100/B) oil prices and drops to 39.1 billion
barrels at lower ($50/B) oil price.
29
Table 7. Economically Recoverable Resources from Applying “State-of-the-Art” CO2-EOR:
National Totals at Base Case Economics*
Basin/Area
Incremental
Technically
Recoverable (Billion
Barrels)
1. Alaska
Incremental
Economically
Recoverable* (Billion
Barrels)
12.4
9.5
2. California
6.3
5.4
3. Gulf Coast (AL, FL, MS, LA)
7.0
2.2
10.6
5.6
1.2
0.5
6. Permian (W TX, NM)
15.9
7.1
7. Rockies (CO,UT,WY)
3.9
1.9
8. Texas, East/Central
17.6
8.3
9. Williston (MT, ND, SD)
2.5
0.5
10. Louisiana Offshore
5.8
3.9
11. Appalachia (WV, OH, KY, PA)
1.6
0.1
84.8
45.0
4. Mid-Continent (OK, AR, KS, NE)
5. Illinois/Michigan
Total
*Base Case Economics use an oil price of $70 per barrel (constant, real) and a CO2 cost of $45 per metric ton ($2.38/Mcf),
delivered at pressure to the field.
30
ȱ
Table 8. Economically Recoverable Resources from Applying “State-of-the-Art” CO2-EOR:
National Totals at Base Case and Alternative Oil Prices/CO2 Costs
Oil Prices
($ per Bbl)
$35
Lower Prices
$50
Base Case
$70
Higher Prices
$90
$100
CO2 Costs
($ per metric ton)
$45*
$55
$60
39.1 BBbls
45.0 BBbls
47.9 BBbls
48.3 BBbls
*A CO2 cost of $45 per metric ton (mt) is equal to $2.38 per Mcf
The estimates of economically recoverable domestic oil from applying CO2-EOR
have been calculated using a minimum financial hurdle rate of 15% (real, before tax).
Higher financial hurdle requirements, appropriate for rapidly installing “state-of-the-art”
CO2-EOR technology in new basins and geologic settings, would reduce the above
(Table 8) volumes of economically recoverable oil.
To examine the impact of a higher financial return on economically recoverable
oil from CO2-EOR, the study applied a higher, 25% (real, before tax) financial hurdle
rate. Under this higher hurdle rate, but still at Base Case oil prices and CO2 costs, the
economically recoverable oil decreases to 38.2 billion barrels. While the higher financial
hurdle rate eliminates a number of economically marginal CO2-EOR prospects, the
great bulk of the fields remain economic, supporting the financial robustness of this oil
recovery technology.
Figure 6 illustrates the volumes of domestic oil recovery potentially available from
applying CO2-EOR technology at alternative oil prices and CO2 costs (using the
assumed relationship in the economic model between oil prices and CO2 costs, shown
in Table 8).
31
32
Figure 6. Economically Recoverable Domestic Oil Resources from Applying CO2-EOR
It is instructive to note that the oil recovery potential from CO2-EOR remains
significant, at 39.1 billion barrels, even under the lower, $50 per barrel, oil price case.
Equally instructive to note is that higher oil prices, by themselves, will not unlock much
more of the large 84.8 billion barrel technically recoverable oil resource available from
state-of-the-art CO2-EOR.
Advances in CO2-EOR technology, as discussed in the previously published
Advanced Resources/DOE report, “Evaluating The Potential For ‘Game Changer’
Improvements In Oil Recovery Efficiency From CO2 Enhanced Oil Recovery”, will be
required to make more of this technically recoverable resource economic.
33
4.0
The Market for Storing CO2 with EOR
The primary purpose of this report is to establish how much CO2, particularly
CO2 emissions captured by power plants, could be stored with enhanced oil recovery.
Chapter 3 established that 39 to 48 billion barrels of economic, incremental
domestic oil could be produced by timely application of CO2-EOR technology. This
chapter draws on this oil recovery assessment to estimate how much CO2, particularly
CO2 emissions captured from new coal-fueled power plants, would be required to
produce this volume of economically recoverable oil, helping establish the market for
captured CO2 emissions.
4.1.
The CO2 Injection and Storage Process
The analysis shows that significant volumes of CO2 (ranging from 10 to 13 billion
metric tons depending on oil price) can be stored with enhanced oil recovery. The
sequence for doing so is as follows:
‚
Initially, purchased CO2, equal to 1 HCPV, is injected along with water for
mobility control.
‚
As oil with CO2 begins to be produced, the CO2 is separated from the oil
and reinjected. As the produced volumes of CO2 increase, these larger
volumes of CO2 are reinjected, continuing the life of the CO2-EOR
project.
‚
Near the end of the CO2-EOR project, the operator may choose to close
the field at pressure, storing essentially all of the injected CO2, or may
inject a large (1 to 2 HCPV) slug of water to recover any remaining mobile
oil and CO2. This CO2 may then be used in another portion of the
reservoir or sold to another oil field.
34
In general, about 5 to 6 Mcf (0.26 to 0.32 metric tons (mt)) of purchased CO2 per
barrel of oil is used and stored as part of CO2-EOR. This is augmented with 5 to 10 Mcf
(0.26 mt to 0.52 mt) of recycled CO2 during the latter stages of a CO2-EOR process.
With incentives for storing CO2 emissions and “next generation” CO2 storage
technology, considerably larger volumes of CO2 could be stored. Additional discussion
of “next generation” storage of CO2 with EOR is provided in Appendix C.
4.2.
Producing “Carbon Free” Domestic Oil
A typical barrel of crude oil contains 0.42 metric tons (mt) of releasable CO2
(assuming that 3% of the produced and refined oil barrel remains as asphalt or coke).
As such, netting the injection and storage of 0.26 to 0.32 mt of CO2 emissions against
the 0.42 mt of CO2 in the produced oil, makes the domestic oil produced by CO2-EOR
about 70% (62% to 76%) “carbon free”.
Two of the alternatives to using domestic oil produced by CO2-EOR have a
much less favorable net CO2 balance. Imported oil is 0% “carbon free” (and results in
additional CO2 emissions from ocean transportation). Domestic corn ethanol is only 10
to 15% “carbon free”, as significant volumes of energy are required for producing the
corn feedstock and final product. When coal is used as the dominant energy source in
ethanol production, corn-based ethanol drops to below 0% “carbon free” and becomes a
contributor to the CO2 emissions problem.
4.3.
The Market for CO2
The market for CO2 from power plant and industrial sources is substantial,
depending on oil prices and CO2 costs. (The CO2 costs used in this study assume that
the CO2 is delivered to the oil field, at pressure.)
Table 9 provides a basin-by-basin tabulation of the volumes of CO2 that would
be required to produce the incremental volumes of economically recoverable domestic
oil from applying CO2-EOR in the Base Case ($70 per barrel oil price and $45 per
metric ton CO2 cost, delivered at pressure).
35
Table 10 provides the aggregate tabulation of the market for CO2 for EOR as a
function of the Base Case oil price and CO2 cost, as well as for three alternative oil
prices (assuming the relationships between oil prices and CO2 costs established in the
economic model). A review of the past history of CO2 costs shows that they have been,
in general, linked to oil prices.
36
Table 9. Economically Feasible Market for CO2 for CO2-EOR: Base Case*
(Eleven Basins/Areas)
Gross Market for
CO2
(million metric
tons)
CO2 Already or
Scheduled to be
Injected
(million metric
tons)
Net New Market for
CO2
(million metric
tons)
1. Alaska
2,094
-
2,094
2. California
1,375
-
1,375
652
**
652
1,443
20
1,423
127
-
127
6. Permian (W TX, NM)
2,712
570
2,142
7. Rockies (CO,UT,WY)
574
74
500
8. Texas, East/Central
1,940
-
1,940
130
-
130
1,368
-
1,368
36
-
36
12,451
664
11,787
Basin/Area
3. Gulf Coast (AL, FL, MS, LA)
4. Mid-Continent (OK, AR, KS, NE)
5. Illinois/Michigan
9. Williston (MT, ND, SD)
10. Louisiana Offshore
11. Appalachia (WV, OH, KY, PA)
Total
*Base Case: Oil price of $70 per barrel; CO2 cost of $45 per metric ton.
37
Table 10. Economically Feasible Market Demand for CO2 by CO2-EOR: Alternative Cases
(Eleven Basins/Areas)
Base Case
($70/Bbl)
(million metric
tons)
Lower Oil
Price Case*
($50/Bbl)
(million metric
tons)
1. Alaska
2,094
1,740
2,214
2,235
2. California
1,375
1,350
1,405
1,405
652
465
805
823
1,423
1,403
1,430
1,430
127
112
141
142
6. Permian (W TX, NM)
2,142
1,696
2,384
2,438
7. Rockies (CO,UT,WY)
500
436
512
514
8. Texas, East/Central
1,940
1,810
2,069
2,069
130
125
148
158
1,368
904
1,599
1,599
36
9
46
46
11,787
10,050
12,753
12,859
Basin/Area
3. Gulf Coast (AL, FL, MS, LA)
4. Mid-Continent (OK, AR, KS, NE)
5. Illinois/Michigan
9. Williston (MT, ND, SD)
10. Louisiana Offshore
11. Appalachia (WV, OH, KY, PA)
Total
Higher Oil Price Cases**
($90/Bbl)
($100/Bbl)
(million
(million metric
metric tons)
tons)
*Lower Oil Price Case: Oil price of $50 per barrel; CO2 cost of $35 per metric ton.
**Higher Oil Price Cases: Oil price of $90 and $100 per barrel; CO2 costs of $55 and $60 per metric ton.
38
4.4.
Market Demand for CO2: Power Plant Perspective
So far, the report has examined the market demand for CO2 from the
perspective of the enhanced oil recovery industry. In this section of the report, we
examine in more detail the market demand for CO2 from the power plant perspective,
giving priority to market demand that might be met by capture and sale of CO2
emissions from the coal-fueled power sector.
The overall demand for CO2 by the CO2-EOR industry can be met by three
potential sources of CO2 supply, namely:
‚
Natural CO2 supplies already found and defined in geological structures;
‚
Industrial, high concentration sources of CO2 that are currently being
captured and used by the CO2-EOR industry; and
‚
The large volumes of power plant and industrial emissions of CO2 that
may need to be captured and stored to meet CO2 management goals.
To better align the CO2 market demand information in this report with the power
sector, the aggregate demand for CO2 of 11,787 million metric tons (223 Tcf) is
presented according to the 14 EIA National Energy Modeling System (NEMS) Electricity
Market Module (EMM),Table 11.
Excluding Alaska, which is not projected to build new coal-fueled power plants to
any great extent, the demand for CO2 in the lower-48 states offered by the EOR
industry is 9,694 million metric tons (183.4 Tcf), Table 11. Figure 7 provides the outline
for the 14 EMM regions; Table 12 provides a simplified crosswalk between the 14 EMM
regions and their included states.
39
JAF02709.PPT
40
Figure 7. Geographical Regions in the NEMS Electricity Market Module
NEMS Regions: CO2 supply and demand have been organized according to the 14
NEMS regions (13 lower-48 plus Alaska) in the Electricity Market Module
Table 11. Economically Feasible Market Demand for CO2 by EOR: NEMS/EMM Power
Generation Regions
NEMS EMM
Region
Demand for CO2 for EOR
Million Metric Tons
Tcf
58
1.1
3,820
72.3
4
0.1
Region 4 – MAIN
100
1.9
Region 5 – MAPP
109
2.1
Region 6 – NY ISO
-
-
Region 7 – NW ISO
-
-
Region 8 – Florida
9
0.2
Region 9 – SERC
2,116
40.0
Region 10 – SWPP
1,570
29.7
Region 11 – WECC/NWPP
411
7.8
Region 12 – WECC/RMPP
120
2.3
Region 13 – WECC/CA
1,376
26.0
Region 14 - Alaska
2,093
39.6
Total U.S.
11,787
223.0
Lower-48
9,694
183.4
Region 1 - ECAR
Region 2 – ERCOT
Region 3 – PJM (MAAC)
*BaseȱCase:ȱ$70/Bblȱoilȱandȱ$45/mtȱCO2.ȱ
41
Table 12. Simplified Crosswalk Between the EMM Regions and States
NEMS EMM
Region
Region 1 - ECAR
Associated State(s)
Kentucky, West Virginia, Ohio, Indiana, Michigan
Region 2 – ERCOT
Region 3 – PJM (MAAC)
Texas
Pennsylvania, Delaware, New Jersey, Maryland
Region 4 – MAIN
Illinois, Missouri, Iowa, Wisconsin
Region 5 – MAPP
North Dakota, South Dakota, Nebraska, Minnesota
Region 6 – NY ISO
New York
Vermont, New Hampshire, Maine, Massachusetts,
Connecticut, Rhode Island
Region 7 – NW ISO
Region 8 – Florida
Region 9 – SERC
Region 10 – SWPP
Florida
Arkansas, Louisiana, Mississippi, Alabama, Tennessee,
Georgia, South Carolina, North Carolina
Region 11 – WECC/NWPP
Oklahoma, Kansas and New Mexico
Washington, Oregon, Idaho, Montana, Wyoming, Utah,
Nevada
Region 12 – WECC/RMPP
New Mexico, Colorado, Arizona
Region 13 – WECC/CA
California
Region 14 - Alaska
Alaska
ȱ
42
Table 13 sets forth the net remaining demand for CO2 by the EOR industry of
7,470 million metric tons for the lower-48 states, after subtracting the 2,224 million
metric tons (42.2 Tcf) of CO2 available, in the next 30 years, from natural CO2 deposits
and high concentration industrial CO2 sources (e.g., natural gas processing plants,
fertilizer plants) already being captured and used for enhanced oil recovery.
Table 14 tabulates the existing sources of CO2, both natural and anthropogenic,
that are currently injected for EOR.
43
Table 13. Economically Feasible Market Demand for CO2 by EOR: NEMS/EMM Power
Generation Regions*
NEMS EMM
Region
Purchased
Natural
CO2
Requirements CO2**
Industrial
CO2**
Unmet (Net)
Demand for CO2
(Tcf)
(Tcf)
(MMcfd)
(Tcf)
(Tcf)
(Million mt)
Region 1 - ECAR
1.1
-
15
***
1.1
58
Region 2 – ERCOT
72.2
25
110
1.2
46.0
2,436
Region 3 – PJM (MAAC)
0.1
-
-
-
0.1
4
Region 4 – MAIN
1.9
-
-
-
1.9
100
Region 5 – MAPP
2.1
-
-
-
2.1
109
Region 6 – NY ISO
-
-
-
-
-
-
Region 7 – NW ISO
-
-
-
-
-
-
Region 8 – Florida
0.2
-
-
-
0.2
9
Region 9 – SERC
40.0
8
-
-
32.0
1,695
Region 10 – SWPP
29.7
5
35
0.4
24.3
1,286
Region 11 – WECC/NWPP
7.8
-
175
1.9
5.9
311
Region 12 – WECC/RMPP
2.3
-
65
0.7
1.6
83
Region 13 – WECC/CA
26.0
-
-
-
26.0
1,377
Region 14 - Alaska
39.6
5
-
-
34.6
1,831
TOTAL U.S.
223.0
43
400
4.2
175.8
9,301
TOTAL Lower-48
183.4
38
400
4.2
141.2
7,470
*BaseȱCase:ȱ$70/Bblȱoilȱandȱ$45/mtȱCO2ȱ
**AssumedȱavailableȱtoȱbeȱproducedȱandȱproductivelyȱusedȱbyȱtheȱCO2ȬEORȱindustryȱinȱtheȱnextȱ30ȱ
years.ȱ
***Lessȱthanȱ0.01ȱTcfȱandȱthusȱnotȱincludedȱinȱtotals.ȱ
44
ȱ
Table 14. Existing CO2 Supplies
(Volumes of CO2 Injected for EOR*)
State/ Province
(storage location)
Source Type
(location)
CO2 Supply MMcfd**
Natural
Anthropogenic
1,700
110
-
240
400
-
Texas-Utah-New MexicoOklahoma
Geologic (Colorado-New Mexico)
Gas Processing (Texas)
Colorado-Wyoming
Gas Processing (Wyoming)
Mississippi
Geologic (Mississippi)
Michigan
Ammonia Plant (Michigan)
-
15
Oklahoma
Fertilizer Plant (Oklahoma)
-
35
Saskatchewan
Coal Gasification (North Dakota)
-
145
2,100
545
TOTAL
* Source: 12th Annual CO2 Flooding Conference, Dec. 2006
** MMcfd of CO2 can be converted to million metric tons per year by first multiplying by 365 (days per year) and then dividing
by 18.9 * 103 (Mcf per metric ton).
The EIA NEMS Electricity Market Model in AEO 2008 projects that 121 new, one
GW size, coal-fueled power plants will come on stream between now and 2030. If
these 121 GWs of coal-fueled power generation capacity were equipped with CCS, they
would provide 20.5 billion metric tons of captured CO2 emissions, assuming 90% CO2
capture, 38% power plant efficiency, 85% operating capacity, and 30 years of
operations. Table 15 sets forth the volumes of CO2 emissions that theoretically would
be available in each of the EMM regions (lower-48) from the installation of these new
coal-fueled power plants.
A closer look at CO2 demand (net, after subtracting CO2 supplies available from
natural and already captured industrial CO2 sources) for EOR shows: (1) there is unmet
(net) demand for CO2 in eleven of the EMM regions that could be filled in part or in
whole by captured CO2 emissions from power plants; and (2) while the overall supply of
CO2 from power plants would more than fulfill the overall (net) CO2 demand from the
EOR industry, Region #13 (WECC, CA) appears to be “short” in terms of CO2 supplies,
due to the absence of new coal-fueled power plant capacity. (Most likely, installation of
45
CO2 pipelines crossing EMM regional boundaries would be used to match CO2
demand with available supply.)
The overall conclusion from the analysis is that CO2-EOR may provide a 7,500
million metric ton market for captured CO2 emissions by the coal-fueled power
generation industry. While the actual revenues afforded by this market will be
established, in the main, by one-on-one negotiations between individual power
companies and oil field operators, the potential size of this market could be large.
Using an oil price of $70 per barrel (Base Case), assuming a delivered CO2 cost
of $45 per metric ton, and subtracting $10 per metric ton for transportation and
handling, the revenue potential offered by the CO2-EOR market could reach $260
billion. In addition, the sale of captured CO2 emissions to the CO2-EOR industry would
enable power companies to avoid the costs and challenges of storing CO2.
46
2.5
12.5
8.2
5.1
KY, WV, OH, IN, MI
FL
PA, DE, NJ, MD
NY
VT, NH, ME, MA, CT, RI
1 ECAR
8 Florida
3 PJM (MAAC)
6 NY ISO
120.9
20,553
-
867
1,394
2,125
425
2,958
561
425
1,088
1,581
-
5,559
3,570
7,471
47
-
-
4
9
58
83
100
109
311
1,286
1,377
1,695
2,438
(13,082)
-
(867)
(1,390)
(2,116)
(367)
(2,875)
(461)
(316)
(777)
(295)
1,377
(3,864)
(1,132)
Shortfall
Available
Demand for
CO2 From CO2 @ $45/mt & (Excess) in
$70/B Oil
CO2 Supply
Coal*
(MMmt)
(MMmt)
(MMmt)
*Assuming all new Coal Plants capture 90% of CO2, operate at 85% capacity and 38% efficiency (8,876 Btu/kWh); includes 30 years of CO2
emissions.
U.S. Total
0.0
17.4
CO, AZ
12 WECC/RMPP
7 NE ISO
3.3
IL, MO, IA, WI
6.4
11 WECC/NWPP WA, OR, ID, MT, WY, UT, NV
4 MAIN
9.3
OK, KS, NM
10 SWPP
2.5
0.0
CA
13 WECC/CA
ND, SD, NE, MN
32.7
AR, LA, MS, AL, TN, GA, SC, NC
9 SERC
5 MAPP
21.0
States
TX
Region
2 ERCOT
EMM
Region
#
Coal
Deployment
2007-2030
(GW)
Table 15. Comparison of Net CO2 Demand (for EOR) with Potential Captured CO2 Emissions from Coal-Fueled Power Plants
5.0
Using Sale of Captured CO2 Emission for “Early Market Entry”
of CCS Technology
As discussed in the previous chapter, CO2-EOR may provide a large, “value
added” market for sale of captured CO2 emissions from power plants and other
industrial sources. Should this market develop in a timely fashion, it would support
“early market entry” of carbon capture and storage (CCS) technology, particularly by
coal-fueled power plants.
5.1.
Economics of CCS
A common feature of EIA carbon management studies is that, in general, CCS is
not considered, as of yet, a key part of the solution 1 , 2 , 3 . The reason, according to EIA’s
EMM cost model, is that using CCS with coal- or gas-fired power is not economically
competitive with other options for generating power with low CO2 emissions, as shown
on Figure 8.
As set forth in EIA’s cost model, incorporation of CCS with new advanced coalfueled power plant currently adds over $20 per MWh of costs, making this a higher cost
option than advanced nuclear power and subsidized wind- or biomass-based electricity
generation. Even by 2020, assuming modest technology progress for advanced coal
and CCS, adding CCS to a coal-fueled power plant would increase electricity generation
and transmission costs by nearly $19 per MWh, keeping this a high cost option.
Figure 8 shows that, according to EIA’ Reference Case for 2020, Advanced Coal
with CCS would entail costs of $81 per MWh of electricity compared to $60 per MWh for
Pulverized Coal without CCS and $66 per MWh for Advanced Nuclear.
ȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱȱ
Energy Market and Economic Impacts of a Proposal to Reduce Greenhouse Gas Intensity with a Cap and Trade Systems, U.S.
DOE, Energy Information Administration, January, 2007.
1
Energy Market Impacts of Alternative Greenhouse Gas Intensity Reduction Goals, U.S. DOE, Energy Information
Administration, March, 2006.
2
Energy Market Impacts of a Clean Energy Portfolio Standard - Follow-up, U.S. DOE, Energy Information Administration,
February, 2007.
3
48
40
50
60
70
80
90
2012
Reference Case
57
66
86
20
62
66
2020
Reference Case
60
81
19
Source: AEO 2008, Reference
Case (Electricity Market Module);
CarBen 2008
*Cost of electricity includes
generation and transmission.
Advanced Nuclear
Advanced Coal w/CCS
Advanced Coal (IGCC)
Pulverized Coal
49
Figure 8. Advanced Coal Plants w/CCS Are Currently Uncompetitive in 2012 and 2020 (EIA’s AEO 2008 Reference Case)
JAF02709.PPT
Cost of Electricity ($/MWh)*
However, revenues from selling captured CO2 emissions into the CO2-EOR
market can change the competitive outlook. For example, as shown in Table 16, the
sale of captured CO2 emissions at $25 to $35 per metric ton can reduce the costs of
power generation with CCS by $17 to $24 per MWh, significantly offsetting the costs of
installing CCS with new coal-fueled power plants.
Table 16. Relationship of CO2 Sales Price to Cost Offsets in the Coal-Fueled
Power Sector (Year 2020)
Sale of CO2
@ $25/mt CO2
7,920 btu/kWh x
94 MMmt CO2/QBtu x
90% Capture
Cost Offset: $16.80/MWh
5.2.
Sale of CO2
@ $35/mt CO2
7,920 btu/kWh x
94 MMmt CO2/QBtu x
90% Capture
Cost Offset: $23.50/MWh
Supporting “Early Market Entry” of CCS Technology
To examine just how much contribution to “early market entry” of CCS may be
possible from sale of captured CO2 emissions into the EOR market, the study
integrated the previously presented CO2 demand information into the CarBen Model’s
version of the DOE/EIA NEMS Electricity Market Module.
The CarBen and EIA EMM Models provide the year 2012 and year 2020 cost
and competitive positions for three coal-fueled power generation options, Table 17.
Table 17. EIA Reference Case Year 2012 and Year 2020 Costs of Electricity
Cost of Electricity $/MWh*
Power Generation Option
Year 2012
Year 2020
1. Pulverized Coal without CCS
$56.60
$59.70
2. Advanced Coal without CCS
$65.70
$62.00
-
$66.00
$86.30
$80.80
3. Advanced Nuclear
4. Advanced Coal with CCS
*Costs include generation and transmission
50
Sale of captured CO2 emissions at $35 per metric ton ($1.85/Mcf) at the plant
gate, equal to $45 per mt ($2.38/Mcf) at the oil field lease line (assuming $10 per mt
($0.53/Mcf) for transportation), would provide a cost offset of $23.50/MWh.
In 2012, the revenue offset of $23.50/MWh from sale of captured CO2 emissions
is not sufficient to make CCS cost competitive. By 2020, however, with assured, longterm sale of captured CO2 emissions at $35 per metric ton (at the plant gate) providing
$23.80/MWh of revenue offsets, new advanced coal plans with CCS would become cost
competitive with alternative, non-CCS coal based power generation options, as shown
in Table 18 and in Figure 9.
Table 18. Cost of Electricity in Year 2020 with Sale of CO2
Power Generation Option
Cost of Electricity (2020)
Initial*
CO2
Final*
Cost
Sale Offset
Cost
($/MWh)
($/MWh)
($/MWh)
1. Pulverized Coal without CCS
$59.70
-
$59.70
2. Advanced Coal without CCS
$62.00
-
$62.00
3. Advanced Nuclear
$66.00
-
$66.00
4. Advanced Coal with CCS
$80.80
($23.50)
$57.30
*Costs are for 2020 and include transmission
The CarBen and EIA EMM models project that 29 new coal-fueled power plants
would be placed into operation between 2013 and 2020 in the lower-48. Assuming that
half of these power plants are favorably located with respect to oil fields attractive for
CO2-EOR and are able to sell CO2 at $35/mt at the plant gate, the integration of CO2
storage and EOR would support the construction of 15 new advanced coal w/CCS
power plants, each with 1 GW of capacity. (A 1 GW advanced coal-fueled power plant
built by 2020 is estimated to be able to sell about 5.1 million metric tons of captured
CO2 emissions per year; 15 plants would be able to provide 2,300 million metric tons in
30 years). Additional sales of captured CO2 emissions by power plants built after 2020
would support additional installations of CCS, as discussed below.
51
40
50
60
70
80
90
JAF02709.PPT
Cost of Electricity ($/MWh)*
66
@ $35/mt
for CO2
57
Advanced
Coal w/EOR
Revenues
2020
81
Source: AEO 2008, Reference
Case (Electricity Market Module);
CarBen 2008
*Cost of electricity includes
generation and transmission.
Advanced Nuclear
Advanced Coal w/CCS
and Sale of CO2
Advanced Coal w/CCS
Advanced Coal (IGCC)
52
Figure 9. Sale of Captured CO2 Emissions Can Help Make Coal Plants w/CCS Competitive
Reference Case
2020
60
62
81
19
Pulverized Coal
5.3.
Adding “Learning” to the “Early Market Entry” Opportunity
The CarBen and EIA EMM models contain a “learning” function which reduces
the costs of installing new technology as a function of the number of CCS installations.
As such, the costs of producing advanced coal-fueled electricity with CCS decline.
The “early market entry” of 15 CCS installations, made possible by the sale of
captured CO2 emissions into the EOR market, helps accelerate the “learning” process.
As such, the costs of producing electricity using advanced coal with CCS are expected
to decline to $74.50/MWh by 2020, as shown in Table 19.
Table 19. Year 2020 Costs of Electricity with Accelerated “Learning”
Based Cost Reductions
Cost of Electricity $/MWh*
Power Generation Option
Year 2020
1. Pulverized Coal without CCS
$59.70
2. Advanced Coal without CCS
$62.00
3. Advanced Nuclear
$66.00
4. Advanced Coal with CCS**
$74.50
*Costs include transmission
**Accelerated “learning” only applied to Advanced Coal with CCS
The significance of the “learning” based cost reductions for advanced coal-fueled
power w/CCS is that now a lower sales price for captured CO2 emissions, at $25/mt
($1.32/Mcf) at the plant gate, equal to $35/mt ($1.85/Mcf) at the oil field lease line,
(assuming $10/mt ($0.53/Mcf) for transportation), would provide sufficient cost offsets of
$16.80/MWh to make advanced coal w/CCS cost competitive.
With assured, long-term sale of captured CO2 at $25 per metric ton at the plant
gate, and assuming cost reductions due to “learning”, new advanced coal plants with
CCS providing electricity at a cost of $58 per MWh would be the preferred economic
choice for the post-2020 time period, as shown in Table 20 and Figure 10.
53
Table 20. Year 2020 Cost of Electricity with “Learning” and CO2 Sale Offset
Power Generation Option
Cost of Electricity (2020)
Initial*
CO2
Final*
Cost
Sale Offset
Cost
($/MWh)
($/MWh)
($/MWh)
1. Pulverized Coal without CCS
$59.70
-
$59.70
2. Advanced Coal without CCS
$62.00
-
$62.00
3. Advanced Nuclear
$66.00
-
$66.00
4. Advanced Coal with CCS
$74.50
($16.80)**
$57.70
*Costs include transmission
**CO2 sale for a plant with EIA Reference Case efficiency and $25/mt CO2 price, at the plant gate.
An additional 80 new (1 GW size) coal-fueled power plants are expected in the
lower-48 between 2020 and 2030. Subtracting the purchase of 2,300 million metric tons
of captured CO2 emissions from 15 plants, the lower-48 EOR market has a remaining
demand for an additional 5,170 million metric tons of CO2. Assuming that a sufficient
number of these plants are favorably located, the unmet demand for CO2 by the EOR
market would support the installation of 34 advanced coal power plants with CCS
between years 2020 and 2030, bringing the total to 49 new power plants with CCS.
The sale of captured CO2 emissions could enable 40% (49 out of 121) of the
new coal-fueled power plants expected to be built between now and 2030 to install
CCS, providing significant assistance toward addressing CO2 emissions in this sector
and helping further drive down the costs of CCS technology.
Additional information on the incorporation of sales of captured CO2 emissions
by power plant into the Electricity Generation Module of the CarBen Model (a simplified
component of the EIA NEMS EMM) is provided in Appendix B.
54
40
50
60
70
80
90
JAF02709.PPT
Cost of Electricity ($/MWh)*
@ $35/mt
for CO2
57
@ $25/mt
for CO2
58
Advanced Coal
w/EOR Revenues
and “Learning”
2020
75
Source: AEO 2008, Reference
Case (Electricity Market Module);
CarBen 2008
*Cost of electricity includes
generation and transmission.
Advanced Coal w/CCS,
“Learning” and Sale of
CO2
Advanced Coal w/CCS
and “Learning”
Advanced Coal w/CCS
and Sale of CO2
Advanced Coal w/CCS
55
Figure 10. Sale of Captured CO2 Emissions Can Help Make Coal Plants w/CCS Competitive.
Advanced Coal
w/EOR Revenues
2020
81
Appendix A
Study Methodology
ȱ
AȬ1
A. STUDY METHODOLOGY
A.1 OVERVIEW. A six part methodology was used to assess the CO2 storage and
EOR potential of domestic oil reservoirs. The six steps were: (1) assembling the Major Oil
Reservoirs Data Base; (2) calculating the minimum miscibility pressure; (3) screening reservoirs
for CO2-EOR; (4) calculating oil recovery; (5) assembling the cost and economic model; and, (6)
performing economic and sensitivity analyses.
A.2 ASSEMBLING THE MAJOR OIL RESERVOIRS DATA BASE. The study
started with the data base used in the previous set of “basins studies”. The study updated and
augmented this data base by incorporating the internally prepared Appalachian Basin Data
Base and by incorporating other improvements to this data base previously performed by
Advanced Resources.
Table A-1 illustrates the oil reservoir data recording format developed by the study. The
data format readily integrates with the input data required by the CO2-EOR screening and oil
recovery models, discussed below. Overall, the Major Oil Reservoirs Data Base contains 2,012
reservoirs, accounting for 74% of the oil expected to be ultimately produced in the U.S. by
primary and secondary oil recovery processes.
ȱ
AȬ2
ȱ
Soi
AȬ3
2002 Water Production (Mbbl)
Daily Water (Mbbl/d)
Bo @ So, swept
Sw
Dykstra-Parsons
ȱ
Type
2002 EOR Production (MMbbl)
Cum EOR Production (MMbbl)
EOR 2002 R eserves (MMbbl)
Ultimate Recovered (MMbbl)
EOR
Daily Inj per Well (Bbl/d)
Injection Wells (shut-in)
2002 Water Injection (MMbbl)
Daily Injection - Field (Mbbl/d)
Cum Injection (MMbbl)
Swi
API Gravity
Viscosity (cp)
Injection
Injection Wells (active)
Swept Zone S o
Sor
Water Production
Boi
Oil Production
Producing Wells (active)
Producing Wells (shut-in)
2002 Production (Mbbl)
Daily Prod - Field (Bbl/d)
Cum Oil Production (MMbbl)
EOY 2002 Oil Reserves (MMbbl)
Water Cut
ARI
Area (A)
Net Pay (ft)
Depth (ft)
Porosity
Reservoir Temp (deg F)
Initial Pressure (psi)
Pressure (psi)
Reservoir Parameters:
Reservoir
Field Name
Basin Name
ARI
ȱ
Table A-1. Reservoir Data Format: Major Oil Reservoirs Data Base
Volumes
ROIP Check (MMbl)
ROIP Volume Check
Swept Zone Bbl/AF
SROIP Check (MMbbl)
Reservoir Volume (AF)
SROIP Volume Check
OOIP Check (MMbl)
Bbl/AF
Reservoir Volume (AF)
OOIP Volume Check
OOIP (MMbl)
P/S Cum Oil (MMbl)
EOY P/S 2002 Reserves (MMbl)
P/S Ultimate Recovery (MMbl)
Remaining (MMbbl)
Ultimate Recovered (%)
ARI P/S
Print Sheets
Considerable effort was required to construct an up-to-date, volumetrically consistent
data base that contained all of the essential data, formats and interfaces to enable the study to:
(1) develop an accurate estimate of the size of the original and remaining oil in-place; (2)
reliably screen the reservoirs as to their amenability for miscible and immiscible CO2-EOR; and,
(3) provide the CO2-PROPHET Model the essential input data for calculating CO2 injection
requirements and oil recovery.
A.3 CALCULATING MINIMUM MISCIBILITY PRESSURE. The miscibility of a
reservoir’s oil with injected CO2 is a function of pressure, temperature and the composition of
the reservoir’s oil. The study’s approach to estimating whether a reservoir’s oil will be miscible
with CO2, given fixed temperature and oil composition, was to determine whether the reservoir
would hold sufficient pressure to attain miscibility. Where oil composition data was missing, a
correlation was used for translating the reservoir’s oil gravity to oil composition.
To determine the minimum miscibility pressure (MMP) for any given reservoir, the study
used the Cronquist correlation, Figure A-1.
This formulation determines MMP based on
reservoir temperature and the molecular weight (MW) of the pentanes and heavier fractions of
the reservoir oil, without considering the mole percent of methane.
(Most Gulf Coast oil
reservoirs have produced the bulk of their methane during primary and secondary recovery.)
The Cronquist correlation is set forth below:
MMP = 15.988*T (0.744206+0.0011038*MW C5+)
Where: T is Temperature in °F, and MW C5+ is the molecular weight of pentanes
and heavier fractions in the reservoir’s oil.
ȱ
AȬ4
ȱ
Figure A-1. Estimating CO2 Minimum Miscibility Pressure
Correlation for CO2 Minimum Pressure as a Function of Temperature
(Mungan, N., Carbon Dioxide Flooding Fundamentals, 1981)
6000
Miscibility Pressure, psi
5000
Mole Weight C5+
300
340
280
260
220
240
200
4000
180
3000
2000
1000
0
70
110
150
190
230
270
Temperature, oF
The temperature of the reservoir was taken from the data base or estimated from the
thermal gradient in the basin. The molecular weight of the pentanes and heavier fraction of the
oil was obtained from the data base or was estimated from a correlative plot of MW C5+ and oil
gravity, shown in Figure A-2.
The next step was calculating the minimum miscibility pressure (MMP) for a given
reservoir and comparing it to the maximum allowable pressure. The maximum pressure was
determined using a pressure gradient of 0.6 psi/foot. If the minimum miscibility pressure was
below the maximum injection pressure, the reservoir was classified as a miscible flood
candidate. Oil reservoirs that did not screen positively for miscible CO2-EOR were selected for
consideration by immiscible CO2-EOR.
ȱ
AȬ5
ȱ
Figure A-2. Correlation of MW C5+ to Tank Oil Gravity
500
y = 4247.98641x-0.87022
R2 = 0.99763
Molecular WT C5+
400
300
200
100
0
0
20
40
60
80
100
Tank Oil Gravity, o API
A.4 SCREENING RESERVOIRS FOR CO2-EOR. The data base was screened for
reservoirs that would be applicable for CO2-EOR. Five prominent screening criteria were used
to identify favorable reservoirs. These were: reservoir depth, oil gravity, reservoir pressure,
reservoir temperature, and oil composition. These values were used to establish the minimum
miscibility pressure for conducting miscible CO2-EOR and for selecting reservoirs that would be
amenable to this oil recovery process. Reservoirs not meeting the miscibility pressure standard
were considered for immiscible CO2-EOR.
The preliminary screening steps involved selecting the deeper oil reservoirs that had
sufficiently high oil gravity. A minimum reservoir depth of 3,000 feet, at the mid-point of the
reservoir, was used to ensure the reservoir could accommodate high pressure CO2 injection. A
minimum oil gravity of 17.5 oAPI was used to ensure the reservoir’s oil had sufficient mobility,
without requiring thermal injection.
A.5
CALCULATING OIL RECOVERY.ȱ ȱ The study utilized CO2-PROPHET to
calculate incremental oil produced using CO2-EOR. CO2-PROPHET was developed as an
alternative to the DOE’s CO2 miscible flood predictive model, CO2PM.
According to the
developers of the model, CO2-PROPHET has more capabilities and fewer limitations than
ȱ
AȬ6
ȱ
CO2PM. For example, according to the above cited report, CO2-PROPHET performs two main
operations that provide a more robust calculation of oil recovery than available from CO2PM:
x
CO2-PROPHET generates streamlines for fluid flow between injection and
production wells, and
x
The model performs oil displacement and recovery calculations along the
established streamlines. (A finite difference routine is used for oil
displacement calculations.)
Even with these improvements, it is important to note the CO2-PROPHET is still primarily
a “screening-type” model, and lacks some of the key features, such as gravity override and
compositional changes to fluid phases, available in more sophisticated reservoir simulators.
A.6
ASSEMBLING THE COST MODEL. A detailed, up-to-date CO2-EOR Cost
Model was developed by the study. The model includes costs for: (1) drilling new wells or
reworking existing wells; (2) providing surface equipment for new wells; (3) installing the CO2
recycle plant; (4) constructing a CO2 spur-line from the main CO2 trunkline to the oil field; and,
(5) various miscellaneous costs.
The cost model also accounts for normal well operation and maintenance (O&M), for
lifting costs of the produced fluids, and for costs of capturing, separating and reinjecting the
produced CO2. A variety of CO2 purchase and reinjection costs options are available to the
model user.
A.7 CONSTRUCTING AN ECONOMICS MODEL. The economic model used by
the study is an industry standard cash flow model that can be run on either a pattern or a fieldwide basis. The economic model accounts for royalties, severance and ad valorem taxes, as
well as any oil gravity and market location discounts (or premiums) from the “marker” oil price.
A variety of oil prices are available to the model user.
ȱ
AȬ7
ȱ
Appendix B
Incorporation of Economically Feasible CO2 Demand for EOR into the
CarBen Model and the Electricity Market Module
Appendix Bȱ
Enabling “Early Market Entry” of CCS Technology in the Electric
Power Sector
The following three tables in Appendix B provide a synopsis of CarBen’s
Electricity Market Model (that emulates the EIA NEMS Electricity Market Module) and
how revenues from sale of CO2 into the EOR industry could help stimulate “early
market entry” of CO2 capture and storage (CCS) by the coal-fueled power sector.
‚
Table B-1 illustrates how the cost of generating and transmitting electricity,
from advanced coal plants (IGCC) and pulverized coal (PC) plants (with
and without CCS) changes with time, from 2012 through 2030. Table B-1
then illustrates how the cost offsets from sale of captured CO2 would help
reduce the cost of electricity and help make the Advanced Coal with CCS
option competitive with coal generated power without CCS.
‚
Table B-2 illustrates the same changes in costs of electricity now with
“accelerated” learning included, from the installation of 49 new advanced
coal plants with CCS.
‚
Table B-3 compares the EIA Reference Case of new coal-fueled power
plant builds (with and without CCS) with the Alternative Case involving
capture and sale of CO2 by the power industry to the CO2-EOR industry.
Table B-2 then summarizes how cost offsets from sale of CO2 (plus
“learning”) in the Alternative Case would enable a significant number of
“early market entries” of power plants with CCS (cumulative):
‚
2020 - - 15 GW size plants w/CCS
‚
2030 - - 48 GW size plants w/CCS
B-1
ȱ
B-1
*Least-cost, competitive preferred power generation option
Price of Electricity w/CCS and Sale of CO2 ($/MWh)
Advanced Coal w/CCS & Sale of CO2 at $35/mt
Advanced Coal w/CCS & Sale of CO2 at $25/mt
Price of Electricity w/o and w/CCS ($/MWh)
Pulverized Coal
Advanced Coal
Advanced Coal w/CCS
Competition Among Coal-Fueled Power Generation Options
CO2-EOR Revenue Offset $35/mt
CO2-EOR Revenue Offset $25/mt
Offset Revenue from Sale of CO2 ($/MWh)
$ 59.60
$ 56.60*
$ 65.70
$ 86.30
2012
2012
ȱ
$ 57.30*
$ 64.00
$ 59.70
$ 62.00
$ 80.80
2020
$ 23.50
$ 16.80
2020
$
$
$
$
$
$
$
52.00*
58.70*
59.10
59.30
75.50
2030
23.50
16.80
2030
x Revenues (cost offsets) from sale of CO2, even without “learning”, can make Advanced Coal plants
w/CCS more economic than Pulverized Coal or Advanced Coal w/o CCS
Economic Implications of Sale of CO2 Without Accelerated “Learning” for Advanced Coal
w/CCS in the CarBen Electricity Market Model
Table B-1
B-2
*Least-cost, competitive preferred power generation option
Price of Electricity w/CCS and Sale of CO2 ($/MWh)
Advanced Coal w/CCS & Sale of CO2 at $35/mt
Advanced Coal w/CCS & Sale of CO2 at $25/mt
Price of Electricity w/o and w/CCS ($/MWh)
Pulverized Coal
Advanced Coal
Advanced Coal w/CCS
Competition Among Coal-Fueled Power Generation Options
CO2-EOR Revenue Offset $35/mt
CO2-EOR Revenue Offset $25/mt
Offset Revenue from Sale of CO2 ($/MWh)
$ 59.60
$ 56.60*
$ 65.70
$ 86.30
2012
2012
ȱ
$ 51.00*
$ 57.70*
$ 59.70
$ 62.00
$ 74.50
2020
$ 23.50
$ 16.80
2020
$
$
$
$
$
$
$
48.10*
54.80*
59.10
59.30
71.60
2030
23.80
16.80
2030
x Revenues (cost offsets) from sale of CO2, plus “learning”, can make Advanced Coal plants w/CCS
more economic than Pulverized Coal or Advanced Coal w/o CCS
Economic Implications of Sale of CO2 and With Accelerated “Learning” for Advanced Coal
w/CCS in the CarBen Electricity Market Model
Table B-2
ȱ
ȱ
ȱ
2012 ¨ 2013-20
12
29
12
22
7
-
2020 ¨ 2021-30
41
80
34
41
7
39
-
B-3
After CO2-Sale
Cumulative Coal Additions (GW )
Pulverized Coal
Advanced Coal (IGCC)
Advanced Coal (IGCC) w/CCS
2012 ¨ 2013-20
12
29
12
11
3
15
-
ȱ
2020 ¨ 2021-30
41
80
23
24
3
22
15
34
Alternative Case: Coal Power Plant Builds with Sales of CO2 to EOR
Reference Case
Cumulative Coal Additions (GW)
Pulverized Coal
Advanced Coal (IGCC)
Advanced Coal (IGCC) w/CCS
Reference Case: Coal Power Plant Builds
2030
121
47
25
49
2030
121
75
46
-
Incorporation of CO2 Sales into the CarBen Electricity Market Model
Table B-3
Appendix C
“Next Generation” CO2 Storage and EOR Technology
Appendix Cȱ
“Next Generation” CO2 Storage and EOR Technology
“Next generation” CO2 storage and enhanced oil recovery technology offers the
potential for storing significantly larger volumes of CO2 than possible using current
practices. Four key technology advances form the heart of “next generation”
technology:
‚
Innovative flood design and well placement, including the application of
vertical (gravity stable) CO2 floods, where geologically feasible, as shown
on Figure C-1;
‚
Extensive use of mobility control techniques, to improve the CO2 flood
mobility ratio and reservoir contact, in both horizontal and vertical CO2
floods, as illustrated in Figure C-2;
‚
Even higher volumes of CO2 injection, beyond the 1 HCPV “standard”
used in “state-of-the-art” CO2 floods, Figure C-3. This would also entail
injecting CO2 into the transition/residual oil zone (TZ/ROZ) and the saline
water zone below the main reservoir section, as shown on Figure C-1;
‚
Making significant investments in “real-time” flood performance
diagnostics and control, as illustrated in Figure C-2, using:
– 4-D seismic;
– Instrumented observation wells;
– Zone-by-zone performance information; and
– Inter-disciplinary technical teams.
To provide an example of how much more CO2 could be stored with EOR, the
study used reservoir simulation to examine the application of CO2 storage and EOR in
an example for Gulf Coast oil reservoir, geologically favorable for either horizontal
(“state-of-the-art”) or gravity stable (“next generation”) CO2-EOR. Table C-1 provides
background information on this example oil reservoir. Table C-2 shows that over six
times as much CO2 could be stored in this reservoir using “next generation” technology,
ȱ
CȬ1
ȱ
enabling the operator to store 1.6 times as much CO2 in the oil reservoir as the CO2
content in the recovered oil.
ȱ
CȬ2
ȱ
ȱ
Original
Original
Water
Oil Contact
Current Water
Oil Contact
Contact
CO22
Injection
CȬ3
CO22 Source
Saline
Saline Reservoir
TZ/ROZ
Unswept Area
Area
Oil Bank
Swept Area
CO2
Recycled
Oil to
to
Market
ȱ
Stage #3
Stage
Stage #2
#2
Stage
Stage #1
#1
Production Well
Well
Figure C-1. Illustration of “Next Generation” Integration of CO2 Storage and EOR
ȱ
JAF0 2709.PPT
Water
Polymer
In Water
Oil and Water
Water
Oil and Water
CȬ4
Viscosity Enhanced Flood
(Improved Mobility Ratio)
Waterflood
(High Mobility Ratio)
Gravity override
•
ȱ
Source: Adapted by Advanced Resources Int’l from “Enhanced
Oil Recovery”, D.W. Green and G. P. Willhite, SPE, 1998.
Addition of viscosity
enhancers would improve
mobility ratio and reservoir
contact.
Viscous fingering
•
Injected CO2 achieves
only limited contact with the
reservoir due to:
Figure C-2. Impact Of Advanced Mobility Control On CO2-EOR Performance
ȱ
ȱ
0
0.2
0.5
1
5
10 20
Mobility Ratio, M
2
M
ȱ
0
0.1
0.2
at
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1.0
pD
s.
50 100 200
500 1000
CȬ5
ȱ
Source: Claridge, E.L., “Prediction of Recovery in Uns table Miscible
Displacement”, SPE (April 1972).
Note: VpD is displaceable fluid pore volumes of CO2 injected.
Sweep Efficiency, EA
Sweep Efficiency in Miscible Flooding
0.2
0.1
0.6
1.0
2.0
1.5
3.0
5.0
V pD
0
0
5
10
15
20
25
10
ȱ
30
20
Years
40
Means (San Andres) @ 2:1 WAG Ratio
50
0.2 HCPV
0.4 HCPV
0.6 HCPV
0.8 HCPV
Injected CO2 vs Oil Recovery
Source: SPE 24928 (1992)
Incremental Tertiary Recovery - % OOIP
Figure C-3. Impact Of Increased CO2 Injection On CO2-EOR Performance
V
v
T.
B.
ȱ
CȬ6
ȱ
Based on the above, the theoretical CO2 storage capacity of this oil reservoir and
structural closure is 2,710 Bcf (143 million tonnes).
• Below the TZ/ROZ is an underlying saline reservoir with 195 feet of thickness,
holding considerable CO2 storage capacity.
• In addition, another 100 million barrels of essentially immobile residual oil exists
in the underlying 130 feet of the transition/residual oil zone (TZ/ROZ).
• The primary/secondary oil recovery in this oil reservoir is favorable at 153
million barrels, equal to 45% of OOIP. Even with this favorable oil recovery
using conventional practices, 187 million barrels is left behind (“stranded”).
Case Study: Large Gulf Coast oil reservoir with 340 million barrels (OOIP) in the
main pay zone has been selected as the “case study”.
Table C-1. Case Study: Integration of “Next Generation” CO2 Storage with EOR
ȱ
13%
64
80%
Storage Capacity Utilization
Oil Recovery (barrels)
% Carbon Neutral (“Green Oil”)
160%
180
76%
109
CȬ7
ȱ
*”Green Oil” means that more CO2 is injected and stored underground than the volume of CO2 contained in the
p roduced oil, once burned.
19
(millions)
(millions)
CO2 Storage (tonnes)
“Next Generation”
“State of the Art”
The additional oil produced is “GREEN OIL”*.
Producing “Green Oil”: Integrating CO2-EOR and CO2 Storage. With
alternative CO2 storage and EOR design, much more CO2 can be stored and
more oil becomes potentially recoverable.
Table C-2. Case Study: Integration of “Next Generation” CO2 Storage with EOR
JAF0270 9.PPT